It should go without saying that it is highly desirable to be able to distinguish between oil and water in a geological formation penetrated by a borehole. The ability to do so enables one to determine, among other things, if a porous formation contains oil or water, the rate of movement and position of the oil/water interface during well production, and whether the water driving fluid has broken through to the production well in a water flood secondary production operation. It has been conventional in the past to distinguish between oil and water by means of a resistivity tool which reads a low resistivity when the formation is saturated with saline water, a good conductor; and a high resistivity when the formation is saturated with oil, an insulator.
It has also been conventional in the past to distinguish between oil and water by taking advantage of the differences in the macroscopic neutron absorption cross section of oil and the normally saline formation water. Since the saline formation water contains chlorine which has a rather high neutron capture cross section and since oil does not, neutron tools have been developed which essentially measure the macroscopic neutron capture cross section (Sigma).
For example, U.S. Pat. No. 3,566,116 (reissued July 8, 1975 as U.S. Pat. No. Re. 28,477); U.S. Pat. Nos. 3,691,378; and 4,055,763 illustrate variations of one such technique for determining Sigma in which a pulsed neutron source is utilized to irradiate the formation with a repetitive burst of fast neutrons in order to permit a time evaluation of the neutron population in the resultant neutron cloud. Typically, this evaluation is accomplished by detecting capture gamma rays which result when thermalized neutrons of the cloud are captured or absorbed by a nucleus of a constituent element in the formation. In such a time evaluation, advantage is taken of the fact that the neutron cloud density decays exponentially, with the characteristic decay time being a function of the macroscopic neutron absorption cross section of the formation. The macroscopic neutron absorption cross section is the sum of the neutron absorption of the elemental constituents of the formation and of its contained fluids.
While these neutron tools and techniques are quite effective in distinguishing between oil and water under normal circumstances, a number of limitations have been encountered. One such limitation is the situation in which, for one reason or another, the non-oil fluid in the formation is fresh water rather than saline water. In this circumstance it is not possible using the above described pulsed neutron technique to distinguish between oil and water since the differences between the neutron capture cross section of the two formation fluids (oil and fresh water) is not large enough to permit their differentiation.
A further limitation that the pulsed neutron techniques for determining Sigma have encountered is their inability to properly determine Sigma in a formation containing large amounts of naturally radioactive elements such as thorium, uranium and potassium. Accumulations of one or more of these radioactive elements may produce a gamma-ray background that obscures the desired information relative to the neutron cloud established by the pulsed neutron source. Unfortunately, accumulations of naturally occurring radioactive elements are often encountered in a producing well. When these radioactive elements are found dissolved in the formation fluids, they may precipitate out of solution and accumulate at the well casing perforations through which the formation fluids are flowed. This creates a radioactive deposit that produces a relatively high gamma-ray background which interferes with the detection method of the pulsed neutron technique. Thus, information regarding Sigma and oil/water movements in the very formation zones of greatest interest may be unavailable due to this obscuring background.
An additional limitation with the pulsed neutron technique is encountered in wells that have fresh water in the well borehole, even though saline water is present in the formation. In such a circumstance, some neutrons from the neutron burst are thermalized and linger in the fresh water of the borehole, giving rise to an interfering "diffusion" background. This effect of course does not occur in those boreholes having saline water since the chlorine is a strong neutron absorber which rapidly scavenges the diffusion neutrons. The "diffusion" background is a particularly bothersome phenomenon for the pulsed neutron technique since the determination of the characteristic decay time following the neutron burst relies on the detection of neutron fluxes whose intensities decrease with time to relatively small values. As a result, the "diffusion" background becomes large relative to the neutron flux of interest so as to obscure the information bearing signal.
In view of the difficulties and limitations inherent in the pulsed neutron technique, one naturally seeks other neutron instruments and techniques that might be suitable for distinguishing between oil and water in those very circumstances there the pulsed technique is lacking. The other conventional neutron instrument used in logging oil wells is commonly referred to as the neutron-neutron tool since it contains a continuous neutron source for irradiating the formation and neutron detectors for detecting the spatial distribution of neutrons established by the source. It is conventional to utilize this tool to measure porosity of the formation under investigation. U.S. Pat. No. 3,483,376, issued Dec. 9, 1969, entitled "TWO NEUTRON DETECTOR EARTH FORMATION POROSITY LOGGING TECHNIQUE", commonly assigned to the assignee of the present invehtion, describes in detail an illustrative embodiment of such a neutron-neutron tool.
Interestingly, in the past, very little has been understood about which parameters of a medium influence porosity response in an investigating instrument. This is indeed the case for neutron-neutron or neutron-gamma porosity tools. Such neutron tools utilize a source for emitting neutrons into the adjacent formations and subsequently or simultaneously detect the spatial distribution of the resultant neutron cloud through either the direct detection of neutrons or through the detection of gamma rays which are created when a neutron is absorbed in the nucleus of an atom of the formation.
Following emission from the source, the neutrons travel through the formation and lose energy by collision with the nuclei of the atoms of the formation. When the energy level of the neutrons is reduced or moderated sufficiently, they may be detected and counted by the investigating instrument. Generally, it is assumed, that primarily the hydrogen index (i.e., the number of hydrogen atoms per unit volume of the formation fluid) is responsible for the spatial distribution of the cloud of neutrons. Since hydrogen is the only element whose nuclear mass resembles that of the neutron, hydrogen is the most effective element in reducing the energy level of the neutrons to a level at which they are eventually detected. In general, the formation pore spaces are filled with either water or liquid hydrocarbons which both contain hydrogen. Thus, this type of neutron log is essentially a record of the hydrogen atom density of the rocks surrounding the borehole. Previously, the neutron log has been considered, therefore, to be a measure of the formation porosity. It is well recognized that gas, on the other hand, will alter this porosity determination since the gas is much less dense than its oil liquid counterpart.
U.S. Pat. No. 4,095,102 issued on June 13, 1978 to Tixier and assigned to the Assignee of the present patent, compares a value of porosity derived from an epithermal neutron-neutron (gamma) tool with a value of porosity derived directly from a measurement of the thermal neutron absorption characteristic of the formation and value of the water component of the formation. Where a difference is noted, hydrocarbon may be expected. In a manner similar to those techniques described earlier that utilize pulses of neutrons to determine a characteristic decay time dependent on macroscopic neutron capture cross section and hence a porosity, the disclosed technique requires saline water in the formation.